1. Technical Field
Embodiments of the subject matter disclosed herein generally relate to methods and valves and, more particularly, to mechanisms and techniques for interrupting a flow of liquid through a valve.
2. Discussion of the Background
During the past years, with the increase in price of fossil fuels, the interest in developing new oil production fields has dramatically increased. However, the availability of land-based production fields is limited. Thus, the industry has now extended drilling to offshore locations, which appear to hold a vast amount of oil reserves. One characteristic of the offshore locations is the high pressure to which the drilling equipment is subjected. For example, it is conventional to have parts of the drilling equipment designed to withstand pressures between 5,000 to 30,000 psi. In addition, the materials used for the various components of the drilling equipment are desired to be corrosion resistant and to resist high temperatures.
Existing technologies for extracting oil from offshore fields use a system 10 as shown in FIG. 1. More specifically, the system 10 includes a vessel (or rig) 12 having a reel 14 that supplies power/communication cables 16 to a controller 18. The controller 18 is disposed undersea, close to or on the seabed 20. In this respect, it is noted that the elements shown in FIG. 1 are not drawn to scale and no dimensions should be inferred from FIG. 1.
FIG. 1 also shows that the drill string 24 is provided inside a riser 40, that extends from vessel 12 to a BOP 28. A wellhead 22 of the subsea well is connected to a casing 44, which is configured to accommodate the drill string 24 that enters the subsea well. At the end of the drill string 24 there is a drill bit (not shown). Various mechanisms, also not shown, are employed to rotate the drill string 24, and implicitly the drill bit, to extend the subsea well.
However, during normal drilling operation, unexpected events may occur that could damage the well and/or the equipment used for drilling. One such event is the uncontrolled flow of gas, oil or other well fluids from an underground formation into the well. Such event is sometimes referred to as a “kick” or a “blowout” and may occur when formation pressure inside the well exceeds the pressure applied to it by the column of drilling fluid (mud). This event is unforeseeable and, if no measures are taken to prevent it, the well and/or the associated equipment may be damaged. Although the above discussion was directed to subsea oil exploration, the same is true for ground oil exploration.
Thus, a blowout preventer (BOP) might be installed on top of the well to seal the well in case that one of the above events is threatening the integrity of the well. The BOP is conventionally implemented as a valve to prevent the release of pressure either in the annular space, i.e., between the casing and the drill pipe, or in the open hole (i.e., hole with no drill pipe) during drilling or completion operations. Recently, a plurality of BOPs are installed on top of the well for various reasons. FIG. 1 shows two BOPs 26 or 28 that are controlled by the controller 18.
However, ultra-deep water exploration presents a host of other drilling problems, such as substantial lost circulation zones, well control incidents, shallow-water flows, etc. Thus, many of these wells are lost due to significant mechanical drilling problems. These events increase the cost of drilling and reduce the chances that oil would be extracted from those wells, which is undesirable.
A new technology for deep water exploration, which is discussed with regard to FIG. 2, has been developed in response to these problems. While the traditional technology used single-gradient drilling, the new technology uses dual-gradient drilling for better controlling a bottom hole pressure, i.e., the pressure at the region around the drill bit 30 shown in FIG. 2. With the single gradient drilling, the bottom hole pressure is controlled by a mud (dedicated mixture of liquids used in the oil extraction industry) column extending from the bottom of the well 32 to the rig 12, as shown in FIG. 2. However, with the dual gradient drilling, a better pressure control is achieved through a combination of (i) mud from the bottom 32 of the well to a mud lift pump 34 and (ii) mud from the mud lift pump 34 to the rig 12. FIG. 2 shows that the new technology employs a mud return line 36 and a seawater power line 38 to the mud lift pump 34 beside the riser 40. The mud is provided through the drill string 24 to the drill bit 30. A subsea rotating device 42 is provided close to the BOP 26 to maintain separation between the sea water in the riser above the subsea rotating device 42 and the mud returns below. Thus, the dual gradient drilling system shown in FIG. 2 provides the mud pumped through the drill string 24 to the drill bit 30 and then pumped back up an annulus between the drill string 24 and the casing 44 by the mud lift pump 34.
The system shown in FIG. 2, which needs to balance the different pressures between the mud and the seawater when the mud lift pump 34 is not active, may employ a drill string valve 46, disposed below BOP 26 and close to drill bit 30. The unbalanced pressure formed because of the U-tube effect of the mud could reach 5,000 psi, depending on mud weight and water depth. This is a large pressure that would normally destroy valves used in faucets, irrigation systems, blood dialysis and other technical fields that use valves. Due to these large pressures and the erosion problems posed by the saltwater and mud, one skilled in the art would not look or import components from valves used in these other technical fields because these valves are not designed to withstand large undersea pressures. Also, the sealing requirements for the drilling industry make those valves used in the low pressure fields inappropriate for the drilling industry.
The conventional drill string valve 46 is placed inside the casing 44, close to the drill bit 30. Thus, the drill string valve 46 is a downhole tool and this valve is illustrated in FIG. 3. The drill string valve 46 has a sliding valve 50 that is configured to seal a passage 52 from a passage 54 inside spring carrier 48. The sliding valve 50 achieves the sealing in concert with cone seal 56. Cone seal 56 may be made of a strong metal and fixed relative to the drill string valve 46. The sliding valve 50 is movable along an axis Z and is biased by a spring 58. The sliding valve 50 is closed in a default position. When the mud is pumped from the vessel 12 towards drill bit 30 (along axis Z in FIG. 2), the high pressure of the mud opens up the sliding valve 50 (by pressing down the sliding valve 50) and compresses spring 58. When the pumping from vessel 12 stops, the compressed spring 58 closes the sliding valve 50, thus closing the drill string valve 46.
A few disadvantages of the drill string valve 46 shown in FIG. 3 are now discussed. A drill collar of the valve was designed in two sections. The two sections include a lower long collar 62 to house the long coil spring 58 and a short upper collar 64 to house the valve mechanism. This design requires machining drill collars to high-precision, making holding diameters and concentricities, especially in deep bores, a challenge. Because it is a two-piece collar, assembly and disassembly requires the use of heavy “tongs” or iron roughneck to make up and break the drill collar connection. This equipment is not available in the shop and must be made up and broken on the drill floor.
A spring package includes the long coil spring 58, or tandem springs that make up a long spring, and these springs are provided in a spring chamber 66. Buckling of the long springs 58 has been observed. The buckling increase a friction between the springs and the package as the coils contact with an outer diameter and an inner diameter of the spring chamber 66. Also, the spring package is open to borehole fluids in this design. Even if the spring area is packed in grease, the grease eventually is replaced with mud during drilling. Thus, the springs are corroded by the borehole fluids, which further increase the friction between the springs and the walls of the spring chambers and also shorten the life of the springs.
Another disadvantage of the system shown in FIG. 3 is related to the way in which the drill string valve 46 is assembled. The coil spring 58 and spring carrier 48 are installed in the long collar 62, where the spring carrier 48 male thread is screwed into a mating thread 63 at the lower end of the collar. Once installed, the spring carrier 48 is extended out of the top of the lower collar 62. The spring extension beyond the collar depends on the spring used, but could be up to 12 inches. This extreme condition would have the free length of the spring hanging out 3 inches beyond the spring carrier 48 with no support. The challenge is to handle the heavy upper collar 64, swallowing an unsupported spring end and having to compress the spring while lining up for engagement with the lower collar thread 65. The spring induced end load during these maneuvers could reach a few thousand pounds at thread engagement. This is a safety concern for the rig operator because of potential injury to the crew.
Accordingly, it would be desirable to provide systems and methods that avoid the afore-described problems and drawbacks.